UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2003
OR
For the transition period from to .
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
Registrant’s telephone number, including area code (918) 588-7000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨.
On July 31, 2003, the Company had 75,120,662 shares of common stock outstanding.
QUARTERLY REPORT ON FORM 10-Q
Part I.
Financial Information
Item 1.
Financial Statements (Unaudited)
Consolidated Statements of Income - Three and Six Months Ended June 30, 2003 and 2002
Consolidated Balance Sheets - June 30, 2003 and December 31, 2002
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2003 and 2002
Consolidated Statement of Shareholders’ Equity and Comprehensive Income - Six Months Ended June 30, 2003
Notes to Consolidated Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
Part II.
Other Information
Legal Proceedings
Changes in Securities and Use of Proceeds
Defaults Upon Senior Securities
Submission of Matters to a Vote of Security Holders
Item 5.
Item 6.
Exhibits and Reports on Form 8-K
Signatures
As used in this Quarterly Report on Form 10-Q, the terms “we”, “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
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Part I - FINANCIAL INFORMATION
Item 1. Financial Statements
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
June 30,
Six Months Ended
(Unaudited)
Revenues
Operating revenues, excluding energy trading revenues
Energy trading revenues, net
Cost of sales
Net Revenues
Operating Expenses
Operations and maintenance
Depreciation, depletion, and amortization
General taxes
Total Operating Expenses
Operating Income
Other income
Other expense
Interest expense
Income taxes
Income from continuing operations
Discontinued operations, net of taxes (Note C)
Income from operations of discontinued component
Gain on sale of discontinued component
Cumulative effect of changes in accounting principle, net of tax (Note A)
Net Income
Preferred stock dividends
Income Available for Common Stock
Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations
Earnings per share from operations of discontinued component
Earnings per share from gain on sale of discontinued component
Earnings per share from cumulative effect of changes in accounting principle
Net earnings per share, basic
Diluted:
Net earnings per share, diluted
Average Shares of Common Stock (Thousands)
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEETS
2003
December 31,
2002
Assets
Current Assets
Cash and cash equivalents
Trade accounts and notes receivable, net
Materials and supplies
Gas in storage
Unrecovered purchased gas costs
Assets from price risk management activities
Other current assets
Assets of discontinued component
Total Current Assets
Property, Plant and Equipment
Production
Gathering and Processing
Transportation and Storage
Distribution
Marketing and Trading
Other
Total Property, Plant and Equipment
Accumulated depreciation, depletion, and amortization
Net Property, Plant and Equipment
Deferred Charges and Other Assets
Regulatory assets, net (Note E)
Goodwill
Prepaid Pensions
Investments and other
Total Deferred Charges and Other Assets
Non-current Assets of Discontinued Component
Total Assets
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Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt
Notes payable
Accounts payable
Dividends payable
Accrued taxes
Accrued interest
Customers’ deposits
Liabilities from price risk management activities
Deferred income taxes
Liabilities of discontinued component
Total Current Liabilities
Long-term Debt, excluding current maturities
Deferred Credits and Other Liabilities
Lease obligation
Other deferred credits
Total Deferred Credits and Other Liabilities
Non-current Liabilities of Discontinued Component
Total Liabilities
Commitments and Contingencies (Note J)
Shareholders’ Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2002
Series D authorized, issued and outstanding 21,815,386 shares at June 30, 2003
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 95,315,952 shares and outstanding 74,920,913 shares at June 30, 2003; issued 63,438,441 shares and outstanding 60,761,064 shares at December 31, 2002
Paid in capital (Note I)
Unearned compensation
Accumulated other comprehensive income (loss) (Note G)
Retained earnings
Treasury stock at cost: 20,395,039 shares at June 30, 2003; and 2,677,377 shares at December 31, 2002
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Operating Activities
Gain on sale of assets
Gain on sale of equity investments
(Income) loss from equity investments
Stock-based compensation expense
Allowance for doubtful accounts
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable
Inventories
Deposits
Accounts payable and accrued liabilities
Price risk management assets and liabilities
Other assets and liabilities
Cash Provided by Continuing Operations
Cash Provided by Discontinued Operations
Cash Provided by Operating Activities
Investing Activities
Changes in other investments, net
Acquisitions
Capital expenditures
Proceeds from sale of property
Proceeds from sale of equity investment
Cash Used in Investing Activities of Continuing Operations
Cash Provided by (Used in) Investing Activities of Discontinued Operations
Cash Used in Investing Activities
Financing Activities
Payments of notes payable, net
Change in bank overdraft
Issuance of debt
Payment of debt issuance costs
Payment of debt
Purchase of Series A Convertible Preferred Stock
Issuance of common stock
Issuance of treasury stock, net
Dividends paid
Cash (Used In) Provided by Financing Activities
Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
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CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
CommonStock
Issued
December 31, 2002
Net income
Other comprehensive income
Total comprehensive income
Re-issuance of treasury stock
Common stock offering
Issuance costs of equity units
Contract adjustment payment
Repurchase of Series A
Convertible Preferred Stock
Exchange of Series A
Issuance of Series D
Issuance of restricted stock
Forfeiture of restricted stock
Registration costs
Stock-based employee compensation expense
Convertible preferred stock dividends
Common stock dividends - $0.51 per share (Note H)
June 30, 2003
See accompanying Notes to the Consolidated Financial Statements.
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(Continued)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Accounting Policies
The accompanying unaudited consolidated financial statements of ONEOK, Inc. and its subsidiaries (“ONEOK” or the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America. The accompanying unaudited consolidated financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of the Company’s business, the results of operations for the three and six months ended June 30, 2003, are not necessarily indicative of the results that may be expected for a twelve-month period. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.
The Company’s accounting policies are consistent with those discussed in its Form 10-K for the year ended December 31, 2002, except as follows.
Critical Accounting Policies
Energy Trading and Price Risk Management Activities - In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, gas in storage and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.
The rescission was effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002, as well as, for contracts entered into on or after October 25, 2002. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 were reported as a cumulative effect of a change in accounting principle on January 1, 2003, resulting in a gross cumulative non-cash loss of $231.0 million, $141.8 million, net of tax, in the first quarter of 2003. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices. Also, as a result of the rescission, the Marketing and Trading segment’s gas in storage inventory is carried on the balance sheet as gas in storage at the lower of cost or market beginning January 1, 2003.
Regulation - In January 2003, Kansas Gas Service (KGS) filed a rate case with the Kansas Corporation Commission (KCC) to increase annual rates approximately $76 million. In July 2003, the KCC staff submitted testimony and a recommended revenue requirement of $28.7 million. Intervenors in the case have recommended revenue ranging from $31 million to $59 million. KGS must submit its rebuttal testimony by August 4, 2003. KGS and the KCC staff will present their testimonies to the commissioners of the KCC during hearings scheduled to begin August 18, 2003. The KCC has until September 29, 2003, to issue a final order in the rate case. If approved, the new rates will be effective in the third quarter of 2003. Until a final order is received, KGS continues to operate under the current rate schedules. Should recovery of any regulatory assets, or portion thereof, be denied by the KCC, these assets may no longer meet the criteria for accounting in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” and, accordingly, a write-off of regulatory assets may be required.
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Significant Accounting Policies
Goodwill - In accordance with the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142), the Company completed its annual analysis of goodwill for impairment as of January 1, 2003 and 2002 and there was no impairment indicated. See Note F.
Asset Retirement Obligations - On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
Statement 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expenses. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.
All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to the 300-megawatt power plant and various processing plants, storage facilities and producing wells. As a result of the adoption of Statement 143, the Company recorded a long-term liability of approximately $16.3 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $12.9 million and a cumulative effect charge of approximately $2.1 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to the consolidated financial statements.
Common Stock Options and Awards - On January 1, 2003, the Company adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) as amended. The Company has elected to begin expensing the fair value of all stock-based compensation granted on or after January 1, 2003 under the prospective method allowed by Statement 123. As a result of the adoption of Statement 123, the Company recorded additional stock-based compensation expense of approximately $483,000, net of tax, during the six months ended June 30, 2003. Prior to January 1, 2003, the Company accounted for its stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations.
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The following table sets forth the effect on net income and earnings per share if the Company had applied the fair-value recognition provisions of Statement 123 to all options granted prior to January 1, 2003.
Net income, as reported
Deduct: Total stock-based employee compensation expense determined under fair value based method for awards granted prior to January 1, 2003, net of related tax effects
Pro forma net income
Earnings per share:
Basic - as reported
Basic - pro forma
Diluted - as reported
Diluted - pro forma
Reclassifications - Certain amounts in the consolidated financial statements have been reclassified to conform to the 2003 presentation.
B. Acquisitions
On January 3, 2003, the Company purchased its Texas assets. The results of these assets have been included in the consolidated financial statements since that date. The Company has paid approximately $432.9 million for these assets, which is subject to adjustment. The primary assets acquired were the gas distribution operations, which serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The acquisition includes a 125-mile natural gas transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also includes natural gas distribution investments in Mexico. The distribution assets are operated under the name Texas Gas Service Company, a division of ONEOK, Inc. The assets and assumed liabilities have been recorded at preliminary fair values. As additional information is obtained, there could be adjustments to the purchase price allocation.
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The table of unaudited pro forma information set forth below presents a summary of consolidated results of operations of the Company as if the acquisition of the assets had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or the results that may be expected in the future.
Pro Forma
June 30, 2002
Operating Revenues
Net revenues
Earnings per share from continuing operations - diluted
Earnings per share - diluted
The addition of the Texas distribution system fits in well with the Company’s concentration in the mid-continent region of the United States, adding to its distribution systems in Oklahoma and Kansas. The acquisition also adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to rate designs heavily weighted toward a fixed customer charge. The regulatory environment in which municipalities set rates diversifies regulatory risk. Other assets acquired with the acquisition complement and enhance the Company’s existing operations in its other business segments.
C. Discontinued Operations
In January 2003, the Company sold approximately 70 percent of the natural gas and oil producing properties of its Production segment (the component) for an adjusted cash price of $294 million. The component is accounted for as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in the financial statements and related notes for all periods shown reflect discontinued operations accounting. The Company’s decision to sell the component was based on strategic evaluations of the Production segment goals and favorable market conditions. The Company recognized a pretax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003. The gain reflects the cash received, less adjustments, selling expenses and the net book value of assets sold.
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The following table discloses the amount of revenues, costs and income taxes reported in discontinued operations for the periods indicated.
Natural gas sales
Oil sales
Other revenues
Operating costs
Operating income
Income from discontinued component
Gain on sale of discontinued component, net of tax of $20.7 million
The following table discloses the major classes of discontinued assets and liabilities included in the Consolidated Balance Sheet for the period indicated.
Assets:
Total current assets of discontinued component
Property, plant, and equipment
Net property, plant, and equipment
Total non-current assets of discontinued component
Total assets of discontinued component
Liabilities:
Total current liabilities of discontinued component
Total non-current liabilities of discontinued component
Total liabilities of discontinued component
D. Price Risk Management Activities and Financial Instruments
The Company’s non-regulated businesses account for derivative instruments and hedging activities in accordance with Statement 133. Under Statement 133, entities are required to record all derivative instruments in the balance sheet at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if
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so, the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately.
As required by Statement 133, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives, strategies for undertaking various hedge transactions and its methods for assessing and testing correlation and hedge ineffectiveness. The Company specifically identifies the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. The Company assesses the effectiveness of its hedging relationships, both at the inception of the hedge and on an on-going basis.
Fair Value Hedges - The Marketing and Trading segment uses swaps to hedge the fair value of certain transportation commitments. At June 30, 2003, net price risk management assets include $12.1 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. Price risk management liabilities include $12.0 million to recognize the change in fair value of the related hedged liability.
The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. During the first quarter of 2003, the Company terminated $50 million in swaps that had a fair value of approximately zero. Currently, $550 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month London InterBank Offered Rate (LIBOR) at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rates were locked in through the first quarter of 2004. At June 30, 2003, price risk management assets include $93.2 million to recognize the fair value of the Company’s derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $93.4 million to recognize the change in fair value of the related hedged liability.
Cash Flow Hedges - The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas inventories. Accumulated other comprehensive income at June 30, 2003, includes gains of approximately $6.0 million, net of tax, related to these hedges that will be realized within the next 19 months.
The Production segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas. The Company realized losses in earnings of approximately $0.8 million and $3.0 million for the three and six months ended June 30, 2003 related to production hedges. The realized losses were reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold. The losses are reported in operating revenues. Accumulated other comprehensive income at June 30, 2003 includes losses of approximately $1.0 million, net of tax, for the production hedges that will be realized in earnings within the next 18 months.
The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At June 30, 2003, KGS had derivative instruments in place to hedge the cost of gas purchases for 8.3 Bcf of gas.
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E. Regulatory Assets
The following table is a summary of the Company’s regulatory assets, net of amortization, for the periods indicated.
Recoupable take-or-pay
Pension costs
Postretirement costs other than pension
Transition costs
Reacquired debt costs
Weather normalization
Line replacements
Regulatory assets, net
F. Goodwill
The following table reflects the changes in the carrying amount of goodwill for the periods indicated.
Total consolidated
The additions to goodwill in 2003 are a result of the preliminary purchase price allocation of the Texas assets acquired in January 2003. See Note B.
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G. Comprehensive Income
The tables below give an overview of comprehensive income for the periods indicated.
Other comprehensive income:
Unrealized gains on derivative instruments
Unrealized holding gains arising during the period
Realized losses in net income
Other comprehensive income before taxes
Income tax expense on other comprehensive income
Comprehensive income
Other comprehensive income (loss):
Unrealized holding gains (losses) arising during the period
Realized gains in net income
Other comprehensive income (loss) before taxes
Income tax benefit (expense) on other comprehensive income (loss)
Other comprehensive income (loss)
Accumulated other comprehensive income reflected in the consolidated balance sheet at June 30, 2003, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.
H. Capital Stock
On January 9, 2003, the Company entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of the Company’s Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting the Company’s two-for-one stock split in 2001, and the Series D shares are convertible into one share of common stock. Some of the differences between the Series D and the Series A are (a) the
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Series D has a fixed quarterly cash dividend of 23.125 cents per share, (b) the Series D is redeemable by ONEOK at any time after August 1, 2006, at a per share redemption price of $20, in the event that the per share closing price of ONEOK common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is convertible into one share of ONEOK common stock, and (d) with certain exceptions, Westar may not convert any shares of Series D held by it unless the annual per share dividend on ONEOK common stock for the previous year is greater than 92.5 cents and such conversion would not subject ONEOK to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. The shareholder agreement restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or group. The agreement allows Westar to sell up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group who does not own more than five percent of ONEOK’s outstanding common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved the Company’s agreement with Westar on January 17, 2003. On February 5, 2003, the Company consummated the agreement by purchasing $300 million of its Series A from Westar. The Company exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of the Company’s newly-created Series D. Upon the cash redemption of the Series A shares, the shares were converted to approximately 18.1 million shares of common stock in accordance with the terms of the Series A shares and the prior shareholder agreement with Westar. Accordingly, the redemption is reflected as an increase to common treasury stock. The Series D exchanged for the Series A was recorded at fair value and the premium over the previous carrying value of the Series A is reflected as a decrease in retained earnings. The Company has registered for resale all of the shares of its common stock held by Westar, as well as all the shares of its Series D issued to Westar and all of the shares of its common stock issuable upon conversion of the Series D. As a result of this transaction and the Company’s early 2003 stock offering, discussed below, Westar’s equity interest in the Company has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.
On January 28 and February 7, 2003, the Company issued 12 million and 1.8 million shares of common stock, respectively, at the public offering price of $17.19 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $16.524 per share, or $228 million in the aggregate.
Also on January 28 and January 31, 2003, the Company issued 14 million and 2.1 million equity units, respectively, at a public offering price of $25 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $24.25 per equity unit, or $390.4 million in the aggregate. Each equity unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due February 16, 2008, issued pursuant to the Company’s existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of the Company’s common stock on January 22, 2003.
Dividends - Quarterly dividends on common stock are $0.17 per share. Due to the timing of the Company’s Board of Directors meetings, dividends on common stock were declared twice in the second quarter of 2003.
I. Paid in Capital
Paid in capital is $763.3 million and $339.7 million for common stock at June 30, 2003, and December 31, 2002, respectively. Paid in capital for convertible preferred stock was $361.7 million and $564.2 million at June 30, 2003, and December 31, 2002, respectively.
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J. Commitments and Contingencies
Southwest Gas Corporation - Two substantially identical derivative actions, which were consolidated, were filed by shareholders against members of the Board of Directors and certain officers of the Company alleging violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned acquisition of Southwest Gas Corporation and waste of corporate assets. The consolidated derivative action has been settled at no significant cost to the Company. The trial Court entered a final judgment on June 24, 2003, approving the settlement by the parties after notice had been given to shareholders.
Environmental- - The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. Remedial investigation has commenced on four sites. However, a comprehensive study is not complete and the results to date do not provide a sufficient basis for a reasonable estimation of the total liability. The liability accrued is reflective of an estimate of the total cost of remedial investigation and feasibility study. Through June 30, 2003, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. The site situations are not common and the Company has no previous experience with similar remediation efforts. The information currently available estimates the cost of remediation to range from $100,000 to $10 million per site based on a limited comparison of costs incurred by others to remediate comparable sites. As such, the information provides an insufficient basis to reasonably estimate a minimum range of the Company’s liability. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. At this time, the Company is not recovering any environmental amounts in rates. The KCC has in the past permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.
Yaggy Facility - In January 2001, the Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed a $180,000 civil penalty against the Company, based on alleged violations of several KDHE regulations. A status conference was held on June 27, 2003, regarding progress toward reaching an agreed upon consent order. The matter was continued for 90 days during pending settlement negotiations. The Company believes there are no long-term environmental effects from the Yaggy storage facility.
Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at the Yaggy facility. These class action lawsuits were filed on the grounds that the eruptions and explosions related to natural gas that allegedly escaped from the Yaggy storage facility. On January 17, 2003, the two-year statute of limitations for known personal injury claims and all non-class members expired. In addition to the two class action matters, sixteen additional lawsuits have been filed against the Company or its subsidiaries seeking recovery for various claims, including property damage, personal injury, loss of business and, in some instances, punitive damages. Although no assurances can be given, the Company believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. The Company is vigorously defending itself against all claims in these cases and believes that its insurance coverage will provide coverage for any material liability associated with these cases.
U.S. Commodity Futures Trading Commission - On January 9, 2003, we received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information regarding certain trading by energy and power marketing firms and information provided by us to energy industry publications. We forwarded our initial response to the subpoena and have provided additional information to the CFTC in
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response to supplemental requests made by the CFTC for additional information. Currently, we are in the process of responding to a request by the CFTC for supplemental information. We intend to comply with the CFTC’s latest request as well as cooperate throughout the CFTC investigatory process. In complying with the subpoena, we have not discovered any information that we believe would adversely affect us.
Labor Negotiations - KGS is currently negotiating with three labor unions to replace collective bargaining agreements that expired on July 31, 2003. Approximately 497 KGS employees are members of those three labor unions, comprising approximately 44% of the total KGS workforce. The Company cannot predict the results of these negotiations. While no assurance can be given that no work stoppage or other disruption will occur, the Company does not believe that this matter will have a material adverse effect on the business, financial condition or results of operations of the Distribution segment or on our company as a whole.
Other - The Company is a party to other litigation matters and claims, which are normal in the course of its operations. While the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, or liquidity.
K. Segments
The accounting policies of the segments are substantially the same as those described in the Summary of Significant Accounting Policies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, except for those changes discussed in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Intersegment sales for the Marketing and Trading segment were $111.0 million and $69.6 million for the three months ended June 30, 2003 and 2002, respectively, and $308.5 million and $208.5 million for the six months ended June 30, 2003 and 2002, respectively. Energy trading contracts included in the following table are reported net of related costs. Corporate overhead costs relating to the reportable segments are allocated for the purpose of calculating operating income. The Company’s equity method investments do not represent operating segments of the Company. The Company has no single external customer from which it receives ten percent or more of its consolidated gross revenues.
In July 2002, the Company completed a transaction to transfer certain transmission assets in Kansas from the Transportation and Storage segment to the Distribution segment. All historical financial and statistical information has been adjusted to reflect the transfer.
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The following tables set forth certain selected financial information for the Company’s six operating segments for the periods indicated.
Transportationand
Storage
Sales to unaffiliated customers
Energy trading contracts, net
Intersegment sales
Total Revenues
Depreciation, depletion and amortization
Income from equity investments
Capital expenditures (continuing operations)
Capital expenditures (discontinued component)
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Marketingand
Trading
Total assets
Income (loss) from equity investments
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L. Supplemental Cash Flow Information
The following table sets forth supplemental information with respect to the Company’s cash flows for the periods indicated.
Cash paid (received) during the period
Interest (including amounts capitalized)
Income taxes received
Noncash transactions
Cumulative effect of changes in accounting principle
Rescission of EITF 98-10 (price risk management assets and liabilities)
Adoption of Statement 143
Dividends on restricted stock
Treasury stock transferred to compensation plans
Issuance of restricted stock, net
Property, plant and equipment
Current assets
Current liabilities
Regulatory assets and goodwill
Other assets
Deferred credits
Cash paid for acquisitions
M. Earnings Per Share Information
Through February 5, 2003, the Company computed its earnings per common share (EPS) in accordance with a pronouncement of the Financial Accounting Standards Board’s Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Company’s Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the “two-class” method of computing EPS. The “two-class” method is an earnings allocation formula that determines EPS for the Company’s common stock and its participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Company’s Series A Convertible Preferred Stock was a participating instrument with the Company’s common stock with respect to the payment of dividends. For the three and six months ended June 30, 2002, and the period from January 1, 2003 to
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February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, EPS for this period reflects this further dilution. As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock in February 2003, the Company no longer applies the provisions of Topic D-95 to its EPS computations beginning in February 2003.
The following tables set forth the computations of the basic and diluted EPS from continuing operations for the periods indicated.
Per Share
Amount
Basic EPS from continuing operations
Income from continuing operations available for common stock
Effect of other dilutive securities:
Options and other dilutive securities
Series D Convertible Preferred Stock dividends
Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed conversion
Convertible preferred stock
Income from continuing operations available for common stock and assumed conversion of preferred stock
Further dilution from applying the “two-class” method
Effect of other dilutive securities
Income from continuing operations available for common stock and assumed exercise of stock options
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Income from continuing operations available for common stock under D-95
Series A Convertible Preferred Stock dividends
Income from continuing operations available for common stock and assumed conversion of Series A Convertible Preferred Stock
Basic EPS from continuing operations under D-95
Income from continuing operations available for common stock not under D-95
Income from continuing operations available for Series D Convertible Preferred Stock dividends
Effect of Other Dilutive Securities
There were 145,474 and 51,839 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2003 and 2002, respectively, since their inclusion would be antidilutive for each
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period. For the six months ended June 30, 2003 and 2002, there were 216,709 and 139,897 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.
The repurchase and exchange of the Company’s Series A Convertible Preferred Stock from Westar in February 2003 was recorded at fair value. In accordance with EITF Topic No. D-42, the premium, or the excess of the fair value of the consideration transferred to Westar over the carrying value, is considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. Since the adoption of Topic D-95, the Company has recognized additional dilution of approximately $94.5 million through the application of the “two-class” method. This additional dilution offsets the total premium recorded, resulting in a net premium of $3.1 million, which is reflected as a dividend on Series A Convertible Preferred Stock in the above EPS calculation for the six months ended June 30, 2003.
N. Debt Covenant Compliance
The Company’s Revolving Credit Facility, which expires September 22, 2003, has customary covenants that relate to liens, investments, fundamental changes in the business, the restriction of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. Other debt agreements have negative covenants that relate to liens and sale/leaseback transactions. At June 30, 2003, the Company was in compliance with all covenants.
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Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward Looking Statements and Risk Factors
Some of the statements contained and incorporated in this Form 10-Q are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of operations and other statements contained or incorporated in this Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “intend,” “believe,” “projection” or “goal.”
You should not place undue reliance on the forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
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Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. We have no obligation and make no undertaking to update publicly or revise any forward-looking statements.
Critical Accounting Policies and Estimates
Energy Trading and Risk Management Activities - We engage in price risk management activities for both energy trading and non-trading purposes. Through 2002, we accounted for price risk management activities for our energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, gas in storage and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.
In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, (Statement 133) are no longer carried at fair value but rather are classified as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the EITF also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market. Therefore, beginning in January 2003, the Marketing and Trading segment’s gas in storage inventory is carried on the balance sheet as gas in storage at the lower of cost or market.
The rescission was effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002, as well as, for contracts entered into on or after October 25, 2002. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 were reported as a cumulative effect of a change in accounting principle on January 1, 2003, resulting in a gross cumulative non-cash loss of $231.0 million, or $141.8 million, net of tax, in the first quarter of 2003. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices.
The fair values of the assets and liabilities recorded pursuant to EITF 98-10 and Statement 133 are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in revenues, on a net basis, in the consolidated statements of income. The fair value of these assets and liabilities reflects management’s best estimate considering various factors, including quoted market prices, time value and volatility underlying the commitments. Market prices were adjusted for the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions.
During the third quarter of 2002, we adopted the applicable provisions of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 provides
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that all mark-to-market gains and losses on derivative contracts held for trading purposes be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The FASB staff also indicated that dealer profits on unrealized gains or losses at contract inception were not appropriate unless evidenced by quoted prices or other market transactions. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3. Net energy trading revenues include sales and purchases of natural gas, crude oil, natural gas liquids and basis, as well as reservation fees. Basis is the price differential that exists between two geographic locations.
Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, Texas Railroad Commission (TRC) and various municipalities in Texas. Certain other of our transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from allocations generally applied by non-regulated operations. Such allocations of costs and revenues made to meet regulatory accounting requirements are considered to be in accordance with generally accepted accounting principles for regulated utilities.
During the ratemaking process, regulatory authorities may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as regulatory assets and amortized to expense as they are recovered through rates. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71) and, accordingly, a write-off of regulatory assets and stranded costs may be required.
In January 2003, KGS filed a rate case with the KCC to increase annual rates approximately $76 million. In July 2003, the KCC staff submitted testimony and a recommended revenue requirement of $28.7 million. Intervenors in the case have recommended revenue ranging from $31 million to $59 million. KGS must submit its rebuttal testimony by August 4, 2003. KGS and the KCC staff will present their testimonies to the commissioners of the KCC during hearings scheduled to begin August 18, 2003. The KCC has until September 29, 2003, to issue a final order in the rate case. If approved, the new rates will be effective in the third quarter of 2003. Until a final order is received, KGS continues to operate under the current rate schedules. Should recovery of any regulatory assets, or portion thereof, be denied by the KCC, these assets may no longer meet the criteria for accounting in accordance with Statement 71 and, accordingly, a write-off of regulatory assets may be required.
Impairment of Long-Lived Assets - We recognize the impairment of a long-lived asset when indicators of impairment are present and the undiscounted cash flow is not sufficient to recover the carrying amount of these assets. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets.
See further discussion of our accounting policies in Note A of Notes to the Consolidated Financial Statements in this Form 10-Q.
Results of Operations
Consolidated Operations
We are a diversified energy company whose objective is to maximize value for shareholders by vertically integrating our business operations from the wellhead to the burner tip. This strategy has led us to focus on acquiring assets that provide synergistic trading and marketing opportunities along the natural gas energy chain. Products and services are provided to our customers through the following segments:
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Transactions - In January 2003, we closed the sale of a significant portion of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million including adjustments. Pursuant to the sale, we sold natural gas and oil reserves in Oklahoma, Kansas and Texas. The sale included approximately 1,900 wells, 482 of which were operated by us. The sale is accounted for as a discontinued operation. Accordingly, the statistical and financial information related to the properties sold has been restated as a discontinued component. We recorded a pre-tax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003.
On January 28, 2003 and February 7, we issued 12 million and 1.8 million shares of common stock, respectively, at the public offering price of $17.19 per share, resulting in net proceeds, after underwriting discounts and commissions, of $16.524 per share, or $228 million in the aggregate.
Also, on January 28 and January 31, 2003, we issued 14 million and 2.1 million equity units, respectively, at a public offering price of $25 per unit, resulting in net proceeds, after underwriting discounts and commissions, of $24.25 per equity unit, or $390.4 million in the aggregate. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003.
On February 5, 2003, we purchased $300 million of our Series A from Westar. These shares were converted to approximately 18.1 million common shares and are being held in treasury stock. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D and retired the Series A shares received in the exchange. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. We have registered for resale all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D. As a result of this transaction and our recently completed stock offering, Westar’s equity interest in ONEOK has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.
On January 3, 2003, we closed the purchase of our Texas assets for a cash purchase price of approximately $432.9 million, which is subject to adjustment. The assets acquired include the third largest gas distribution business in Texas, with operations that serve approximately 535,000 customers, over 90 percent of which are residential. The distribution assets are operated under the name of Texas Gas Service (TGS).
During the second quarter of 2002, we settled a number of outstanding issues pending before the OCC. We had previously recorded a charge of approximately $34.6 million in the fourth quarter of 2001 related to
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these matters. As a result of the settlement agreement, we revised the estimated amount of the charge and reversed $14.2 million of the charge in the second quarter of 2002.
We sold our claim related to the Enron bankruptcy for $22.1 million resulting in a gain of $14.0 million in the first quarter of 2002. The sale was subject to normal representations as to the validity, but not collectibility, of the claim and guarantees from Enron. We had previously recorded a charge of $37.4 million in the fourth quarter of 2001 related to the Enron bankruptcy.
Adoption of New Accounting Standards - On January 1, 2003, we adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. As a result of the adoption of Statement 143, we recorded a cumulative effect of a change in accounting principle charge of approximately $2.1 million, net of $1.3 million in taxes, in the first quarter of 2003.
On January 1, 2003, we adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123), as amended. We have elected to begin expensing the fair value of all stock-based compensation granted on or after January 1, 2003, under the prospective method allowed by Statement 123, as amended. As a result of the adoption of Statement 123, we recorded additional stock-based compensation expense of approximately $483,000, net of taxes, during the six months ended June 30, 2003.
In October 2002, the EITF of the FASB rescinded EITF 98-10. As a result, energy related contracts that are not accounted for pursuant to Statement 133, will no longer be carried at fair value but rather will be accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss of $141.8 million, net of $89.2 million in taxes, in the first quarter of 2003.
During the third quarter of 2002, we adopted EITF 02-3. EITF 02-3 provides that all mark-to-market gains and losses on derivative contracts held for trading purposes be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented.
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The following table sets forth certain selected financial information for the periods indicated.
Financial Results
Cost of gas
Discontinued operations, net of taxes
Cumulative effect of changes in accounting principle, net of tax
Operating Results - Operating revenues and cost of gas increased in the three and six months ended June 30, 2003, compared to the same periods in 2002, primarily due to increases in commodity prices and the acquisition of the Texas assets. The decrease in energy trading revenues, net for the three-month period is primarily related to the impact of the rescission of EITF 98-10. Prior to its rescission, net revenues were recognized under fair value accounting as physical natural gas inventories were injected into storage, normally during the second and third quarters. The rescission of EITF 98-10 requires that natural gas inventories under storage agreements be carried at the lower of cost or market and precludes mark-to-market accounting for energy related contracts that do not qualify as derivatives. The revenue will be recognized as the gas is withdrawn from storage and sold, normally in the first and fourth quarters. Energy trading revenues, net, increased during the six-month period due to the comparatively colder temperatures during the winter heating season. In addition, we continue to capture the significant intra-month price volatility and inter-region inefficiencies that have occurred during 2003 through our continued use of storage and transport capacity. Operating costs and depreciation, depletion and amortization have increased in 2003, compared to 2002, primarily due to the acquisition of the Texas assets. The TGS addition contributed approximately $22.7 million and $54.6 million to net revenues and $1.4 million and $15.8 million to operating income for the three and six months ended June 30, 2003, respectively.
Our Production segment currently owns, develops and produces natural gas and oil reserves in Oklahoma. Our strategy is to add value to our existing oil and gas production operations. Accordingly, we focus on acquiring and developing reserves rather than exploratory drilling.
In January of 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million including adjustments. The sale included approximately 1,900 wells, 482 of which we operated. We recorded an after-tax gain of $38.4 million ($59 million pre-tax) in the first quarter of 2003 related to this sale. The statistical and financial
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information related to the properties sold has been restated as a discontinued component for all periods presented.
The following tables set forth certain financial and operating information for our Production segment for the periods indicated.
Other income (expense), net
Cumulative effect of change in accounting principle, net of tax
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Operating Information
Proved reserves
Continuing operations
Gas (MMcf)
Oil (MBbls)
Discontinued component
Average realized price (a)
Gas ($/Mcf)
Oil ($/Bbls)
Capital expenditures (Thousands)
Operating Results - Natural gas sales from continuing operations increased for the three and six months ended June 30, 2003, compared to the same period in 2002, due to higher prices received in 2003. Production from our retained wells in the second quarter of 2003 was slightly lower than production in the second quarter of 2002 due to normal production declines. Production for the first six months of 2003 is higher than the comparable 2002 period as a result of drilling during 2002 that increased production from our retained properties in early 2003. Prices before hedges were $5.13 and $3.19 per Mcf in the second quarter of 2003 and 2002, respectively. Prices before hedges were $5.70 and $2.22 for the six months ended June 30, 2003 and 2002, respectively.
At June 30, 2003, we had approximately 12.5 MMcf per day, or 60 percent, of our anticipated gas production for the remainder of 2003 hedged at a NYMEX price of $4.50 per Mcf. We hedged 5 MMcf per day, or 25 percent, of 2004 anticipated production hedged at a NYMEX price of $5.30 per Mcf.
Oil sales decreased for the three-month period ended June 30, 2003, compared to the same period in 2002, due to lower realized prices in the second quarter of 2003 compared to the same period in 2002, while production slightly increased. The production increase reflects drilling and recompletions during the second half of 2002, which resulted in increased oil volumes in 2003, partially offset by normal production declines. The average oil price before hedges for the second quarter of 2003 was $24.28 per barrel. There were no oil hedges in place for the second quarter of 2002.
Oil sales increased for the six months ended June 30, 2003 compared to the same period in 2002, due to both price and production volume increases. Volumes produced were higher in the first six months of 2003 compared to 2002 as a result of successful drilling in the second half of 2002, which resulted in higher
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production in the first part of 2003. At June 30, 2003, we have approximately 64 percent of our anticipated oil production for the remainder of 2003 hedged at $27.25 per barrel.
Operating costs for continuing operations increased for the three and six months ended June 30, 2003 compared to the same periods in 2002 due to higher overhead costs on retained wells and higher production taxes caused by higher realized prices.
Our Production segment added 5.0 Bcfe of net reserves for the six months ended June 30, 2003, including 1.6 Bcfe of proved developed, which is comprised of 1.2 Bcfe of proved developed producing and 0.4 Bcfe of proved developed non-producing, and 3.4 Bcfe of proved undeveloped reserves.
Operational Highlights - The Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of natural gas liquids (NGLs). Our Gathering and Processing segment currently has a processing capacity of approximately 2.0 Bcf/d (Bcf per day), of which approximately 0.2 Bcf/d is currently idle. Our Gathering and Processing segment owns approximately 14,000 miles of gathering pipelines that supply our gas processing plants.
In January 2003, we acquired a retail propane business through our purchase of the Texas assets. This business consists of a small retail propane distribution business in Austin and a retail propane bottle and delivery service primarily serving El Paso.
The following tables set forth certain selected financial and operating information for our Gathering and Processing segment for the periods indicated.
Natural gas liquids and condensate sales
Gas sales
Gathering, compression, dehydration and processing fees and other revenues
Cumulative effect of a change in accounting principle, net of tax
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Total gas gathered (MMMBtu/d)
Total gas processed (MMMBtu/d)
Natural gas liquids sales (MBbls/d)
Natural gas liquids produced (MBbls/d)
Gas sales (MMMBtu/d)
Operating Results - The increases in NGL and condensate sales revenues for the three and six months ended June 30, 2003, compared to same periods in 2002, are primarily due to additional third party sales volumes, increases in composite NGL prices and increases in crude oil prices. Continued restructuring of contracts has allowed us to mitigate exposure to unfavorable keep-whole spreads. The Conway OPIS composite NGL price based on our NGL product mix increased from $0.39 and $0.36 per gallon for the three and six months ended June 30, 2002, respectively, to $0.54 and $0.59 per gallon for the same periods in 2003. The average NYMEX crude oil price increased from $26.16 and $22.74 per barrel for the three and six months ended June 30, 2002, respectively, to $29.27 and $31.63 per barrel for the same periods in 2003.
The increases in gas sales and cost of sales for the three and six months ended June 30, 2003, compared to the same periods in 2002, are primarily due to increases in the price of natural gas and NGLs. Gas sales also increased as a result of additional volumes available due to reduced NGL recovery because of the high value of natural gas relative to NGL prices. Average natural gas price for the mid-continent region increased from $3.15 and $2.68 per MMBtu for the three and six months ended June 30, 2002, respectively, to $5.00 and $5.55 per MMBtu for the same periods in 2003. These increases were partially offset by reduced volumes as a result of the sale of certain Oklahoma gas gathering and processing assets in December 2002.
The decreases in operating costs for the three and six-month periods are due to the sale of the Oklahoma assets and lower bad debt expense. These decreases were partially offset by higher leased compression costs and additional operating costs as a result of the acquisition of the Texas assets.
Operating Highlights - Our Transportation and Storage segment represents our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. We own or control capacity in five storage facilities in Oklahoma, three in Kansas and three in Texas, with a combined working capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle. Our intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC, and TRC, respectively. In July 2002, we completed a transaction to transfer certain transmission assets in Kansas to our affiliated distribution company in Kansas. Historical financial and statistical information have been adjusted to reflect this transfer. In December 2002, certain Oklahoma storage property rights were sold and a long-term agreement was entered into with the purchaser, whereby we retain storage capacity consistent with our historical usage.
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The following tables set forth certain selected financial and operating information for our Transportation and Storage segment for the periods indicated.
Transportation and gathering revenues
Storage revenues
Gas sales and other
Cost of fuel and gas
Volumes transported (MMcf)
Operating results -Transportation and gathering revenues increased for the three and six months ended June 30, 2003, compared to the same periods in 2002, primarily due to the price of natural gas and its impact on the valuation of retained fuel. Average natural gas price for the mid-continent region increased from $3.15 and $2.68 per MMBtu for the three and six months ended June 30, 2002, respectively, to $5.00 and $5.55 per MMBtu for the same periods in 2003. Storage revenues increased primarily due to additional working capacity being available in 2003, compared to the same periods in 2002, as a result of restoring previously idled storage capacity. The sale of gas inventory in 2002 also provided additional capacity. Gas sales and other revenues decreased for the three and six-month periods in 2003, compared to same periods in 2002, due to a reduction in sales volumes associated with our wellhead purchases on certain gathering facilities in Oklahoma. In addition, gas sales and other decreased for the six-month period due to reduced gas inventory sales.
Cost of fuel and gas decreased for the three and six months ended June 30, 2003, compared to same periods in 2002, due to a decrease in costs related to gas inventory sales and decreased volumes associated with our wellhead purchases. This decrease was partially offset by higher natural gas prices for fuel. The three and six-month periods in 2002 also included higher costs due to adjustments related to the reconciliation of third party contractual storage and pipeline positions.
The decrease in operating costs for the three and six-month periods in 2003, compared to the same periods in 2002, is due to lower litigation costs, bad debt expenses and ad valorem taxes. These decreases were partially offset by higher leased compression costs.
Capital expenditures decreased primarily as the result of a large power generation project being completed in the first quarter of 2002.
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Our Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through our Kansas Gas Service (KGS) division, which serves residential, commercial, industrial, end-use transportation and wholesale customers. Operations in Oklahoma are conducted through our Oklahoma Natural Gas (ONG) division, which serves residential, commercial, industrial customers and end-use transportation and wholesale customers. Operations in Texas are conducted through our Texas Gas Service (TGS) division, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 75 percent, 80 percent, and 17 percent of the populations of Kansas, Oklahoma and Texas, respectively. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by the various municipalities which it serves, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the TRC.
KGS is currently negotiating with three labor unions to replace collective bargaining agreements that expired on July 31, 2003. Approximately 497 of our KGS employees are members of those three labor unions, comprising approximately 44% of the total KGS workforce. We cannot predict the results of these negotiations. While no assurance can be given that no work stoppage or other disruption will occur, we do not believe that this matter will have a material adverse effect on the business, financial condition or results of operations of our Distribution segment or on our company as a whole.
On January 3, 2003, we purchased our Texas gas distribution assets. The gas distribution operations serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville, and others. Over 90 percent of the customers are residential. The acquisition adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to rate designs that are heavily weighted toward a fixed customer charge.
In January 2003, KGS filed a rate case with the KCC to increase annual rates approximately $76 million. On July 11, 2003, the KCC staff submitted testimony and a recommended revenue requirement of $28.7 million. Intervenors in the case have recommended revenue ranging from $31 million to $59 million. KGS must submit its rebuttal testimony by August 4, 2003. KGS and the KCC staff will present their testimonies to the commissioners of the KCC during hearings scheduled to begin August 18, 2003. The KCC has until September 29, 2003, to issue a final order in the rate case. If approved, the new rates will be effective in the third quarter of 2003. Until a final order is received, KGS will continue to operate under the current rate schedules. Should recovery of any regulatory assets, or portions thereof, be denied by the KCC, these costs may no longer meet the criteria of Statement 71 and, accordingly, may be required to be written-off.
A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding cases pending before the OCC. The major cases settled were the Commission’s inquiry into our gas cost procurement practices during the winter of 2000/2001; an application seeking relief from improper and excessive purchased gas costs; and enforcement action against us, our subsidiaries and affiliated companies of ONG. In addition, all of the open inquiries related to the annual audits of ONG’s fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.
The Stipulation has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million. In December 2005, a final billing credit will be made to customers. The minimum amount of this credit is estimated to be approximately $2.8 million. ONG is replacing certain gas contracts, which are expected to reduce gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage gas are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved will be added to the final billing credit
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scheduled to be provided to customers in December 2005. ONG operating income increased in the second quarter of 2002 by $14.2 million as a result of this settlement.
In July 2002, we completed a transaction to transfer certain transmission assets in Kansas from the Transportation and Storage segment to the Distribution segment. Historical financial and statistical information have been adjusted to reflect these changes.
The following table sets forth certain selected financial information for our Distribution segment for the periods indicated.
Gross margin
Transportation revenues
Operating results - The increase in gas sales and cost of gas for the three and six months ended June 30, 2003, compared to the same period in 2002, is primarily due to the addition of TGS and increased commodity prices. Additionally, cost of gas for the three and six months ended June 30, 2003 was higher, compared to the same periods in 2002, due to the $14.2 million reduction in the second quarter of 2002 resulting from the OCC Stipulation. Additional sales volumes in Kansas and Oklahoma due to colder weather in the first quarter of 2003, compared to the same period in 2002, increased gas sales and cost of gas for the six months ended June 30, 2003, compared to the same period in 2002.
The change in gross margin for the three and six months ended June 30, 2003 is due to the addition of TGS, offset in part by the $14.2 million gas cost reduction in the second quarter of 2002 resulting from the OCC Stipulation.
Operating costs and depreciation, depletion and amortization increased for the three and six months ended June 30, 2003, compared to the same periods in 2002, due primarily to the addition of TGS, increased bad debt expense resulting from higher gas costs and higher employee costs.
The addition of TGS contributed approximately $22.7 million and $54.6 million to net revenues and $1.4 million and $15.8 million to operating income for the respective three and six-month periods ended June 30, 2003, respectively.
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The following table sets forth certain operating information for our Distribution segment for the periods indicated.
Volumes (MMcf)
Residential
Commercial
Industrial
Wholesale
Public authority
Total volumes sold
Transportation
Total volumes delivered
Overall, volumes increased primarily as a result of the addition of TGS. Additionally, residential and commercial volumes increased in the three and six months ended June 30, 2003, compared to the same periods in 2002, as a result of colder weather in Kansas and Oklahoma. Wholesale sales in Kansas, also known as “as available” gas sales represent gas volumes available under contracts that exceed the needs of our residential and commercial customer base and are available for sale to other parties. Wholesale volumes increased for the three months ended June 30, 2003 over the same period in 2002 due to increased volumes available for sale; however, wholesale volumes decreased for the six-month period as greater volumes were required to meet the needs of the Kansas residential, commercial, and industrial customers due to colder weather during the first quarter of 2003. Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.
Transportation volumes, which include pipeline capacity leased to others and transportation for end-use customers, increased primarily due to the addition of transportation customers acquired with the Texas assets. Volumes also increased due to commercial and industrial customers moving to new transportation rates, a marketing effort to add small-usage customers and a reduction in the minimum volume required for transport service in Oklahoma.
The following table sets forth certain selected operating information for our Distribution segment for the periods indicated.
Average number of customers
Customers per employee
The average number of customers and customers per employee increased in 2003 compared to the same periods in 2002 due to the addition of TGS and their favorable ratio of customers per employee.
Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. See Note E of the Notes to Consolidated Financial Statements for a detail of regulatory assets at June 30, 2003.
Operational Highlights - Our marketing and trading operation purchases, stores, markets, and trades natural gas to both the wholesale and retail sectors throughout most of the United States. We have strong mid-continent region storage positions and transport capacity of 1 Bcf/d that allow us to trade natural gas
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throughout most of the United States. With the addition of 5 Bcf of storage at July 1, 2003, we have total storage capacity of 75 Bcf. With our storage capacity, we have withdrawal capability of 2.3 Bcf/d and injection capability of 1.4 Bcf/d. We have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We continue to enhance our strategy of focusing on higher margin business which includes providing reliable service during peak demand periods through the use of storage and transportation capacity.
We have a 300-megawatt electric power generating plant located in Oklahoma adjacent to one of our natural gas storage facilities that is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium,” which is the value added by converting natural gas to electricity, during peak demand periods.
During the third quarter of 2002, we adopted certain provisions of EITF 02-3, which provides that all mark-to-market gains and losses on derivative contracts held for trading purposes be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. Prior to the third quarter of 2002, our energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented. EITF 02-3 does not affect power-related revenues, which will continue to be reported on a gross basis.
In October 2002, the EITF rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement 133 will no longer be carried at fair value, but rather will be accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy-trading inventories carried under storage agreements should no longer be carried at fair value, but should be carried at the lower of cost or market.
The rescission is effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applies immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for gas in storage and existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss, net of tax, of $141.8 million. The impact from this change was non-cash. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods.
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The following tables set forth certain selected financial and operating information for our Marketing and Trading segment for the periods indicated.
Power sales
Cost of power and fuel
Natural gas sales volumes (MMcf)
Natural gas gross margin ($/Mcf)
Power sales volumes (MMwh)
Power gross margin ($/Mwh)
Physically settled volumes (MMcf)(a)
Operating Results
Energy trading revenues include revenues related to trading natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price differential that exists between trading locations relative to the Henry Hub natural gas price. We began actively trading crude oil and natural gas liquids in this segment in the first quarter of 2002.
Net revenues decreased for the three months ended June 30, 2003, compared to the same period in 2002, while sales volumes increased. The increase in sales volumes is attributable to additional marketing and trading opportunities that have developed with the recent downsizing of certain trading companies in our industry. The offsetting decrease in net revenues is attributable the rescission of EITF 98-10 effective January 1, 2003. Historically, net revenues were recognized under fair value accounting as physical natural gas inventories were injected into storage during the second and third quarters. With the rescission of EITF 98-10, natural gas inventories carried under storage agreements are no longer carried at fair value, but rather are accounted for on an accrual basis at lower of cost or market with revenues recorded when the gas is sold, typically in the first and fourth quarters.
Net revenues derived from our physical trading totaled $26.1 million in the second quarter of 2003. In addition, net revenues for the second quarter of 2003 included $13.3 million, which represents the change
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in fair value of our derivative instruments subject to fair value accounting pursuant to Statement 133 at June 30, 2003 (excluding those instruments qualifying for hedge accounting). Net revenues for the second quarter of 2002 included mark-to-market earnings of $66.1 million, which represented the change in net trading price risk management assets and liabilities from March 31, 2002 to June 30, 2002, resulting from the application of mark-to-market accounting on all energy contracts pursuant to EITF 98-10. The higher margins derived from physical trading are attributable to continued execution of our strategy that focuses on trading around physical assets and the use of storage and transport capacity to capture intra-month price volatility and inter-region inefficiencies. Margins realized from our retail gas business increased by $1.0 million for the second quarter of 2003, compared to the same period in 2002, due to our expanding customer base in Wyoming and Nebraska. Margins realized from our wholesale power business increased by $1.1 million for the second quarter of 2003, compared to the same period in 2002, due to comparatively better spark spreads in the Southwest Power Pool.
Net revenues increased for the six months ended June 30, 2003, compared to the same period in 2002, due to comparatively colder temperatures during the winter heating season and additional marketing and trading opportunities. In addition, our use of storage and transport capacity allowed us to capture the significantly higher intra-month price volatility and inter-region inefficiencies that have occurred in 2003 compared to 2002. Our storage and transport capacity also enabled us to secure positive option value and realize favorable pricing spreads on stored gas volumes. In the first quarter of 2002, we sold our Enron bankruptcy claim, which added $10.4 million to our net revenues.
Liquidity and Capital Resources
General - A part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow and borrowings from a combination of commercial paper, bank lines of credit, and capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources, together with possible equity financings, such as our recent public common stock and equity unit offerings, for liquidity and capital resource needs on both a short and long-term basis. During 2002 and through the second quarter of 2003, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2003 are expected to be $215 million compared to $233 million in 2002. The decrease in capital expenditures due to the sale of our oil and gas producing properties in January 2003 and reductions in the Gathering and Processing segment is partially offset by the increase due to the acquisition of our Texas assets.
Financing is provided through our commercial paper program, long-term debt and, as needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and the sale/leaseback of facilities.
Our credit rating is currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (negative outlook) by Moody’s Investor Service. Our credit rating may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit rating are the debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper would increase, resulting in an increase in our cost to borrow funds. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to an $850 million revolving credit facility, which expires September 22, 2003 and which we intend to renew.
Our energy marketing and trading business relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit support requirements with several counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activity could be significantly limited. Without an investment grade rating, we would be required to fund margin requirements with the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable
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instruments. At June 30, 2003, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $26.2 million.
We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, recoverability and timing of recovery of regulated natural gas costs, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and debt capacity are adequate to meet our liquidity requirements associated with commodity price volatility. We also have no material guarantees of debt or other commitments to unaffiliated parties.
Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the poor performance of the equity market and lower interest rates, the market value of our pension fund assets has decreased and, accordingly, our pension benefit for our pension and supplemental retirement plans will decrease in 2003 from $20.8 million to $7.0 million. Should the value of our pension fund assets fall below our Accumulated Benefit Obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan as deemed necessary.
Westar - On January 9, 2003, we entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of our Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting our two-for-one stock split in 2001, and the Series D shares are currently convertible into one share of common stock. Some of the differences between the Series D and Series A are (a) the Series D has a fixed annual cash dividend of 92.5 cents per share, (b) the Series D is redeemable by us at any time after August 1, 2006, at a redemption price of $20, in the event that the closing price of our common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is currently convertible into one share of our common stock, and (d) Westar may not convert any shares of Series D held by it unless the annual per share dividend on our common stock for the previous year is greater than 92.5 cents and such conversion would not subject us to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. Our new shareholder agreement with Westar restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or to a group. The agreement allows Westar to sell up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group that does not own more than five percent of our common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved our agreement with Westar on January 17, 2003. On February 5, 2003, we consummated the agreement by purchasing $300 million of our Series A from Westar. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D. In addition, we have registered all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D. As a result of this transaction and our recently completed common stock offering, Westar’s ownership interest in our company has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.
Cash Flow Analysis
Operating Cash Flows – Operating cash flows decreased in the six months ended June 30, 2003 compared to the same period in 2002, despite a significant increase in income from continuing operations. The decreases in operating cash flows primarily relate to changes in working capital and deferred income taxes. The change in inventories for the six-month period in 2003 compared to 2002 is due to the rescission of EITF 98-10, which requires that gas in storage be carried at the lower of cost or market at June 30, 2003,
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and no longer included in price risk management assets as it was at December 31, 2002. The change in unrecovered purchased gas costs (UPGC) for the six-month period in 2003 compared to 2002 is primarily due to the unusually high recovery of UPGC in the first quarter of 2002 related to previously deferred UPGC due to an OCC order. The changes in price risk management assets and liabilities primarily relate to the change in mark-to-market income and derivative contracts that expired and were settled in 2003. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Fluctuations in these accounts, period-to-period, reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.
In 2002, operating cash flows were positively impacted by the collection of accounts receivable and reduced deposits. Accounts receivable decreased for the six-month period ended June 30, 2002, due to the decrease in energy prices and decreased demand in the summer months. The reduction in restricted deposits for the same period is due to increased purchases of option contracts by our Marketing and Trading segment in the six months ended June 30, 2002. The change in UPGC is primarily due to the unusually high recovery of UPGC in the first quarter of 2002 related to deferred UPGC at December 31, 2001, due to an OCC order.
Investing Cash Flows – Acquisitions in 2003 represent the cash purchase of the Texas assets. Cash provided by investing activities of discontinued operations represents the sale of natural gas and oil producing properties for a cash sales price of $294 million, including adjustments, of which $15 million was received in 2002.
Financing Cash Flows - Our capitalization structure is 39 percent equity and 61 percent long-term debt at June 30, 2003, compared to 47 percent equity and 53 percent long-term debt at December 31, 2002. There were no short-term notes or commercial paper payable at June 30, 2003. Our capitalization structure including notes payable was 43 percent equity and 57 percent total debt at December 31, 2002. The change in our capital structure is primarily due to the issuance of common stock and equity units in January 2003, which was partially offset by the payment of notes payable and the repurchase of our Series A Convertible Preferred Stock from Westar in February 2003. At June 30, 2003, we had $1.9 billion of long-term debt outstanding. As of that date, we could have issued $1.0 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.
Both Standard and Poors and Moody’s Investment Services consider the equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust the capitalization structure. Standard and Poors considers the equity units to be equal amounts of debt and equity for the first three years, with the effect being to increase shareholders’ equity by the same amount as debt, which would result in a capitalization structure of 46 percent equity and 54 percent long-term debt at June 30, 2003. Moody’s Investment Services considers 25 percent of the equity units to be debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 49 percent equity and 51 percent long-term debt at June 30, 2003.
Our $850 million revolving credit facility is primarily used to support our commercial paper program. At June 30, 2003, we had no commercial paper outstanding and had approximately $158 million in temporary investments.
On January 28 and February 7, 2003, we issued 12 million and 1.8 million shares of common stock, respectively, at the public offering price of $17.19 per share, resulting in net proceeds to us, after underwriting discounts and commissions, of $16.524 per share, or $228 million in the aggregate.
Also, on January 28 and January 31, 2003, we issued 14 million and 2.1 million equity units, respectively, at a public offering price of $25 per unit, resulting in net proceeds to us, after underwriting discounts and commissions, of $24.25 per share, or $390.4 million in the aggregate. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5% (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes
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will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. The present value of the contract adjustment payments is accounted for as equity and reduces Paid In Capital. Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003, and a floor of $17.19 per share.
On April 4, 2003, we filed an amendment to a shelf registration statement on Form S-3 for the issuance and sale by ONEOK of common stock, preferred stock, purchase contracts, purchase units and debt securities, and the issuance and sale by ONEOK Capital Trust I and ONEOK Capital Trust II of trust preferred securities, in one or more offerings with an aggregate offering price of up to $1.0 billion. Also, on April 4, 2003, we filed a shelf registration statement on Form S-3 to register for resale by Westar all of the shares of our common stock held by Westar, as well as all the shares of our Series D Convertible Preferred Stock issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D Convertible Preferred Stock. Both of these registration statements have been declared effective by the Securities and Exchange Commission.
Impact of Recently Issued Accounting Pronouncements
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (Statement 150). Statement 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liability and equity. The statement requires that an issuer classify a financial instrument that is within its scope as a liability. Financial instruments that do not meet the criteria of Statement 150 are to be accounted for according to previous requirements. Statement 150 is effective for financial instruments entered into or modified after May 31, 2003, and is effective at the beginning of the first interim period beginning after June 15, 2003. Currently, we have no financial instruments that are within the scope of Statement 150.
Item 3.Quantitative and Qualitative Disclosures About Market Risk
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Form 10-K for the year ended December 31, 2002, except as follows.
KGS uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect KGS customers from upward volatility in the market price of natural gas. At June 30, 2003, KGS had derivative instruments in place to hedge the cost of purchases for 8.3 Bcf of gas. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.
TGS uses derivative instruments to mitigate the volatility of the cost of gas to protect its customers in the city of El Paso. At June 30, 2003, TGS had no derivative instruments in place to hedge the cost of purchases of gas. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment.
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The following table provides a detail of our Marketing and Trading segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contracts and their related hedges are not included in the following table. This maturity schedule is consistent with our Marketing and Trading segment’s trading strategy.
Source of Fair Value (1)
Total
fair
value
Prices actively quoted (2)
Prices provided by other external sources (3)
For further discussion of trading activities and assumptions used in our trading activities, see the Critical Accounting Policies in Notes A and D of the notes to consolidated financial statements included in this Form 10-Q.
Interest Rate Risk - At June 30, 2003, the interest rate on 69.8% of our long-term debt was fixed after considering the impact of interest rate swaps. During the first quarter of 2003, we terminated $50 million in swaps that had a fair value of approximately zero. Currently, $550 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month London InterBank Offered Rate (LIBOR) at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rates were locked in through the first quarter of 2004. The swaps will result in an estimated $23.0 million in savings during 2003. At June 30, 2003, price risk management assets include $93.2 million to recognize the fair value of derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $93.4 million to recognize the change in fair value of the related hedged liability. Interest expense decreased approximately $0.1 million for the three months ended June 30, 2003, and increased approximately $1.1 million for the six months ended June 30, 2003 to recognize the ineffectiveness of these hedges.
A 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by approximately $32,000 before taxes. This amount is limited based on the LIBOR locks that we have in place through the first quarter of 2004. If these locks were not in place, a 100 basis point change in the interest rates would affect our annual interest expense by $5.5 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.
Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $1.7 million and $2.0 million at June 30, 2003 and 2002, respectively.
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The following table details the average, high and low VAR calculations:
Value at Risk
Average
High
Low
The variations in the VAR data are reflective of our marketing and trading growth and market volatility during the quarter.
Item 4.Controls and Procedures
Quarterly Evaluation of the Company’s Disclosure Controls - We evaluated the effectiveness of the design and operation of our “disclosure controls and procedures” (Disclosure Controls) as of the end of the period covered by this Quarterly Report. This evaluation (the Controls Evaluation) was done under the supervision and with the participation of management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the Securities and Exchange Commission (SEC) require that in this section of the Quarterly Report we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls based on and as of the date of the Controls Evaluation.
Disclosure Controls – Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Limitations on the Effectiveness of Controls – Our management, including the CEO and CFO, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, including our Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures that may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
Scope of the Controls Evaluation – The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in this Quarterly Report. In the course of the Controls Evaluation, we sought to identify data errors, control problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation will be done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in our Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K. The overall
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goals of these evaluation activities are to monitor our Disclosure Controls and to make modifications as necessary. Our intent in this regard is that the Disclosure Controls will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.
Since the date of the Controls Evaluation to the date of this Quarterly Report, there have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.
Conclusions – Based upon the Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in providing reasonable assurance of achieving their objective of timely alerting them to material information required to be disclosed by us in periodic reports we file with the SEC.
PART II - OTHER INFORMATION
Item 1.Legal Proceedings
In re ONEOK, Inc. Derivative Litigation, No. CJ-2000-00593, District Court of Tulsa County, Oklahoma (formerly Gaetan Lavalla, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al., No. CJ-2000-598 and Hayward Lane, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al.). This consolidated derivative action has been settled at no significant cost to us. The trial Court entered a final judgment on June 24, 2003 approving the settlement by the parties after due notice had been given to the shareholders as required by the Court and relevant statutes. This case will have no further effect on us or our officers and directors as the time to file an appeal has expired.
Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30. On May 12, 2003, plaintiffs served their motion to file a fourth amended petition and proposed fourth amended petition. On July 28, 2003, the Court entered an order allowing plaintiffs to file the fourth amended petition. The fourth amended petition (i) does not name ONEOK Gas Transportation, L.L.C., as a defendant (or any other defendant who had objected to personal jurisdiction), (ii) limits the purported class to royalty owners and non-working interest owners, (iii) limits the wells as to which claims are asserted to those in Kansas, Colorado and Wyoming, and (iv) limits the claims asserted to conspiracy and unjust enrichment.
In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. A status conference was held on June 27, 2003 regarding the progress toward reaching an agreed upon consent order. The matter was continued for ninety (90) days during the pendency of settlement negotiations.
U.S. Commodity Futures Trading Commission. On January 9, 2003, we received a subpoena from the U.S. Commodity Futures Trading Commission, CFTC, requesting information regarding certain trading by energy and power marketing firms and information provided by us to energy industry publications. We forwarded our initial response to the subpoena and have provided additional information to the CFTC in response to supplemental requests by the CFTC for additional information. Currently, we are in the process of responding to a request by the CFTC for supplemental information. We intend to comply with the CFTC’s latest request as well as cooperate throughout the CFTC investigatory process. In complying with the subpoena and additional requests made by the CFTC, we have not discovered any information that we believe would adversely affect us.
Item 2.Changes in Securities and Use of Proceeds
Not Applicable.
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Item 3.Defaults Upon Senior Securities
Item 4.Submission of Matters to Vote of Security Holders
We held our 2003 annual meeting of shareholders on May 15, 2003. At this meeting, the individuals set forth below were elected by a plurality vote to our board of directors for a term of three years:
Directors Elected
William L. Ford, Class C
Douglas Ann Newsom, Class C
Gary D. Parker, Class C
The individuals set forth below are the members of our board of directors whose term of office as a director continued after the meeting:
Continuing Directors
William M. Bell,Class A
David L. Kyle, Class B
Bert H. Mackie, Class B
Pattye L. Moore, Class A
J.D. Scott, Class A
Mollie B. Williford, Class B
In addition, at the annual meeting the appointment of KPMG LLP as our independent auditor for the 2003 fiscal year was ratified by our shareholders as follows:
Appointment of KPMG LLP as principal independent auditor
Item 5.Other Information
Our Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries was subject to a “blackout period,” as defined in Regulation BTR (Blackout Trading Restriction), in connection with our quarterly payment of dividends. The blackout period commenced on July 25, 2003, and ended on July 31, 2003. During that blackout period, the ability of all participants in the plan to purchase, sell or otherwise acquire or transfer an interest in plan assets, to make changes in investment options, to initiate distributions or loans and to change payroll deferral percentages was suspended. All of our common stock was subject to the blackout period. The person designated by us to respond to inquiries about the blackout period was Robin Lacy, ONEOK, Inc., 100 West Fifth Street, Tulsa, OK 74103, 918-588-7063. We received notice of the blackout period from the plan administrator on June 19, 2003, as required by Section 101(i)(2)(E) of the Employment Retirement Income Security Act of 1974. This disclosure is provided pursuant to Item 11 of Form 8-K.
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Item 6.Exhibits and Reports on Form 8-K
Exhibits
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
Exhibit Description
Reports on Form 8-K
We filed the following Current Reports on Form 8-K during the quarter ended June 30, 2003.
May 1, 2003 – Furnished the Company’s results of operations for the quarter ended March 31, 2003.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Registrant
Date: August 4, 2003
/s/ Jim Kneale
Jim Kneale
Senior Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer)
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